This section is intended to introduce various aspects of the prior art. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admission of prior art.
The production of hydrocarbons from a reservoir oftentimes carries with it the incidental production of non-hydrocarbon gases. Such gases include contaminants such as carbon dioxide (CO2) and hydrogen sulfide (H2S). When CO2 and H2S are produced as part of a hydrocarbon gas stream (such as methane (C1) or ethane (C2)), the gas stream is sometimes referred to as “sour gas.”
Sour gas is usually treated to remove CO2, H2S, and other contaminants before it is sent downstream for further processing or sale. Removal of acid gases creates a “sweetened” hydrocarbon gas stream. The sweetened stream may be used as an environmentally-acceptable fuel or as feedstock to a chemicals or gas-to-liquids facility. The sweetened gas stream may be chilled to form liquefied natural gas, or LNG.
The gas separation process creates an issue as to the disposal of the separated contaminants. In some cases, the concentrated acid gas (consisting primarily of H2S and CO2) is sent to a sulfur recovery unit (“SRU”). The SRU converts the H2S into benign elemental sulfur. However, in some areas (such as the Caspian Sea region), additional elemental sulfur production is undesirable because there is a limited market. Consequently, millions of tons of sulfur have been stored in large, above-ground blocks in some areas of the world, most notably Canada and Kazakhstan.
While the sulfur is stored on land, the carbon dioxide associated with the acid gas is oftentimes vented to the atmosphere. However, the practice of venting CO2 is sometimes undesirable. One proposal to minimize CO2 emissions is a process called acid gas injection (“AGI”). AGI means that unwanted sour gases are re-injected into a subterranean formation under pressure and sequestered for potential later use. Alternatively, the carbon dioxide is used to create artificial reservoir pressure for enhanced oil recovery operations.
To facilitate AGI, it is desirable to have a gas processing facility that effectively separates out the acid gas components from the hydrocarbon gases. Some natural gas reservoirs contain relatively low percentages of hydrocarbons (less than 40%, for example) and high percentages of acid gases, principally carbon dioxide, but also hydrogen sulfide, carbonyl sulfide, carbon disulfide, and various mercaptans. In these instances, cryogenic gas processing may be beneficially employed.
Cryogenic gas processing is a distillation process sometimes used for gas separation. However, conventional cryogenic distillation towers may be bulky and/or create weight distribution issues for offshore vessels and platforms. Moreover, for gas streams having unusually high levels of CO2 (such as greater than about 30 mol. percent), additional processing may be needed to remove methane that becomes entrained in the bottoms liquid stream, or to remove carbon dioxide that becomes entrained in the overhead gas stream.
Challenges also exist with respect to cryogenic distillation of sour gas. For example, at higher CO2 concentrations, e.g., greater than about 5 mol. percent at total pressure less than about 700 psig, CO2 may freeze out as a solid in the cryogenic distillation tower. The formation of CO2 as a solid disrupts the cryogenic distillation process.
Therefore, there is a need for improved cryogenic distillation systems, which resolve one or more of the problems identified above.